Active controlled bottomhole pressure system &amp; method

ABSTRACT

A wellbore drilling system has an umbilical that carries a drill bit in a wellbore. Drilling fluid pumped into the umbilical discharges at the drill bit bottom and returns through an annulus between the umbilical and the wellbore carrying entrained drill cuttings. An active differential pressure device (APD device), such as a jet pump, turbine or centrifugal pump, in fluid communication with the returning fluid creates a differential pressure across the device, which alters the pressure below or downhole of the device. The APD device can be driven by a positive displacement motor, a turbine, an electric motor, or a hydraulic motor. A controller controls the operation of the APD device in response to programmed instructions and/or one or more parameters of interest detected by one or more sensors. A preferred system is a closed loop system that maintains the wellbore at under-balance condition, at-balance condition or over-balance condition.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. provisional patentapplication serial No. 60/323,803 filed on Sep. 20, 2001, titled “ActiveControlled Bottomhole Pressure System and Method.”

FIELD OF THE INVENTION

[0002] This invention relates generally to oilfield wellbore drillingsystems and more particularly to drilling systems that utilize activecontrol of bottomhole pressure or equivalent circulating density duringdrilling of the wellbores.

BACKGROUND OF THE ART

[0003] Oilfield wellbores are drilled by rotating a drill bit conveyedinto the wellbore by a drill string. The drill string includes a drillpipe (tubing) that has at its bottom end a drilling assembly (alsoreferred to as the “bottomhole assembly” or “BHA”) that carries thedrill bit for drilling the wellbore. The drill pipe is made of jointedpipes. Alternatively, coiled tubing may be utilized to carry thedrilling of assembly. The drilling assembly usually includes a drillingmotor or a “mud motor” that rotates the drill bit. The drilling assemblyalso includes a variety of sensors for taking measurements of a varietyof drilling, formation and BHA parameters. A suitable drilling fluid(commonly referred to as the “mud”) is supplied or pumped under pressurefrom a source at the surface down the tubing. The drilling fluid drivesthe mud motor and then discharges at the bottom of the drill bit. Thedrilling fluid returns uphole via the annulus between the drill stringand the wellbore inside and carries with it pieces of formation(commonly referred to as the “cuttings”) cut or produced by the drillbit in drilling the wellbore.

[0004] For drilling wellbores under water (referred to in the industryas “offshore” or “subsea” drilling) tubing is provided at a work station(located on a vessel or platform). One or more tubing injectors or rigsare used to move the tubing into and out of the wellbore. In riser-typedrilling, a riser, which is formed by joining sections of casing orpipe, is deployed between the drilling vessel and the wellhead equipmentat the sea bottom and is utilized to guide the tubing to the wellhead.The riser also serves as a conduit for fluid returning from the wellheadto the sea surface.

[0005] During drilling, the drilling operator attempts to carefullycontrol the fluid density at the surface so as to control pressure inthe wellbore, including the bottomhole pressure. Typically, the operatormaintains the hydrostatic pressure of the drilling fluid in the wellboreabove the formation or pore pressure to avoid well blow-out. The densityof the drilling fluid and the fluid flow rate largely determine theeffectiveness of the drilling fluid to carry the cuttings to thesurface. One important downhole parameter controlled during drilling isthe bottomhole pressure, which in turn controls the equivalentcirculating density (“ECD”) of the fluid at the wellbore bottom.

[0006] This term, ECD, describes the condition that exists when thedrilling mud in the well is circulated. The friction pressure caused bythe fluid circulating through the open hole and the casing(s) on its wayback to the surface, causes an increase in the pressure profile alongthis path that is different from the pressure profile when the well isin a static condition (i.e., not circulating). In addition to theincrease in pressure while circulating, there is an additional increasein pressure while drilling due to the introduction of drill solids intothe fluid. This negative effect of the increase in pressure along theannulus of the well is an increase of the pressure which can fracturethe formation at the shoe of the last casing. This can reduce the amountof hole that can be drilled before having to set an additional casing.In addition, the rate of circulation that can be achieved is alsolimited. Also, due to this circulating pressure increase, the ability toclean the hole is severely restricted. This condition is exacerbatedwhen drilling an offshore well. In offshore wells, the differencebetween the fracture pressures in the shallow sections of the well andthe pore pressures of the deeper sections is considerably smallercompared to on shore wellbores. This is due to the seawater gradientversus the gradient that would exist if there were soil overburden forthe same depth.

[0007] In some drilling applications, it is desired to drill thewellbore at at-balance condition or at under-balanced condition. Theterm at-balance means that the pressure in the wellbore is maintained ator near the formation pressure. The under-balanced condition means thatthe wellbore pressure is below the formation pressure. These twoconditions are desirable because the drilling fluid under suchconditions does not penetrate into the formation, thereby leaving theformation virgin for performing formation evaluation tests andmeasurements. In order to be able to drill a well to a total wellboredepth at the bottomhole, ECD must be reduced or controlled. In subseawells, one approach is to use a mud- filled riser to form a subsea fluidcirculation system utilizing the tubing, BHA, the annulus between thetubing and the wellbore and the mud filled riser, and then inject gas(or some other low density liquid) in the primary drilling fluid(typically in the annulus adjacent the BHA) to reduce the density offluid downstream (i.e., in the remainder of the fluid circulationsystem). This so-called “dual density” approach is often referred to asdrilling with compressible fluids.

[0008] Another method for changing the density gradient in a deepwaterreturn fluid path has been proposed, but not used in practicalapplication. This approach proposes to use a tank, such as an elasticbag, at the sea floor for receiving return fluid from the wellboreannulus and holding it at the hydrostatic pressure of the water at thesea floor. Independent of the flow in the annulus, a separate returnline connected to the sea floor storage tank and a subsea lifting pumpdelivers the return fluid to the surface. Although this technique (whichis referred to as “dual gradient” drilling) would use a single fluid, itwould also require a discontinuity in the hydraulic gradient linebetween the sea floor storage tank and the subsea lifting pump. Thisrequires close monitoring and control of the pressure at the subseastorage tank, subsea hydrostatic water pressure, subsea lifting pumpoperation and the surface pump delivering drilling fluids under pressureinto the tubing for flow downhole. The level of complexity of therequired subsea instrumentation and controls as well as the difficultyof deployment of the system has delayed (if not altogether prevented)the practical application of the “dual gradient” system.

[0009] Another approach is described in U.S. patent application Ser. No.09/353,275, filed on Jul. 14, 1999 and assigned to the assignee of thepresent application. The U.S. patent application Ser. No. 09/353,275 isincorporated herein by reference in its entirety. One embodiment of thisapplication describes a riser less system wherein a centrifugal pump ina separate return line controls the fluid flow to the surface and thusthe equivalent circulating density.

[0010] The present invention provides a wellbore system wherein thebottomhole pressure and hence the equivalent circulating density iscontrolled by creating a pressure differential at a selected location inthe return fluid path with an active pressure differential device toreduce or control the bottomhole pressure. The present system isrelatively easy to incorporate in new and existing systems.

SUMMARY OF THE INVENTION

[0011] The present invention provides wellbore systems for performingdownhole wellbore operations for both land and offshore wellbores. Suchdrilling systems include a rig that moves an umbilical (e.g., drillstring) into and out of the wellbore. A bottomhole assembly, carryingthe drill bit, is attached to the bottom end of the drill string. A wellcontrol assembly or equipment on the well receives the bottomholeassembly and the tubing. A drilling fluid system supplies a drillingfluid into the tubing, which discharges at the drill bit and returns tothe well control equipment carrying the drill cuttings via the annulusbetween the drill string and the wellbore. A riser dispersed between thewellhead equipment and the surface guides the drill string and providesa conduit for moving the returning fluid to the surface.

[0012] In one embodiment of the present invention, an active pressuredifferential device moves in the wellbore as the drill string is moved.In an alternative embodiment, the active differential pressure device isattached to the wellbore inside or wall and remains stationary relativeto the wellbore during drilling. The device is operated during drilling,i.e., when the drilling fluid is circulating through the wellbore, tocreate a pressure differential across the device. This pressuredifferential alters the pressure on the wellbore below or downhole ofthe device. The device may be controlled to reduce the bottomholepressure by a certain amount, to maintain the bottomhole pressure at acertain value, or within a certain range. By severing or restricting theflow through the device, the bottomhole pressure may be increased.

[0013] The system also includes downhole devices for performing avariety of functions. Exemplary downhole devices include devices thatcontrol the drilling flow rate and flow paths. For example, the systemcan include one or more flow-control devices that can stop the flow ofthe fluid in the drill string and/or the annulus. Such flow-controldevices can be configured to direct fluid in drill string into theannulus and/or bypass return fluid around the APD device. Anotherexemplary downhole device can be configured for processing the cuttings(e.g., reduction of cutting size) and other debris flowing in theannulus. For example, a comminution device can be disposed in theannulus upstream of the APD device.

[0014] In a preferred embodiment, sensors communicate with a controllervia a telemetry system to maintain the wellbore pressure at a zone ofinterest at a selected pressure or range of pressures. The sensors arestrategically positioned throughout the system to provide information ordata relating to one or more selected parameters of interest such asdrilling parameters, drilling assembly or BHA parameters, and formationor formation evaluation parameters. The controller for suitable fordrilling operations preferably includes programs for maintaining thewellbore pressure at zone at under-balance condition, at at-balancecondition or at over-balanced condition. The controller may beprogrammed to activate downhole devices according to programmedinstructions or upon the occurrence of a particular condition.

[0015] Exemplary configurations for the APD Device and associated driveincludes a moineau-type pump coupled to positive displacementmotor/drive via a shaft assembly. Another exemplary configurationincludes a turbine drive coupled to a centrifugal-type pump via a shaftassembly. Preferably, a high-pressure seal separates a supply fluidflowing through the motor from a return fluid flowing through the pump.In a preferred embodiment, the seal is configured to bear either or bothof radial and axial (thrust) forces.

[0016] In still other configurations, a positive displacement motor candrive an intermediate device such as a hydraulic motor, which drives theAPD Device. Alternatively, a jet pump can be used, which can eliminatethe need for a drive/motor. Moreover, pumps incorporating one or morepistons, such as hammer pumps, may also be suitable for certainapplications. In still other configurations, the APD Device canb bedriven by an electric motor. The electric motor can be positionedexternal to a drill string or formed integral with a drill string. In apreferred arrangement, varying the speed of the electrical motordirectly controls the speed of the rotor in the APD device, and thus thepressure differential across the APD Device.

[0017] Bypass devices are provided to allow fluid circulation in thewellbore during tripping of the system, to control the operating setpoints of the APD Device and/or associated drive/motor, and to provide adischarge mechanism to relieve fluid pressure. For examples, the bypassdevices can selectively channel fluid around the motor/drive and the APDDevice and selectively discharge drilling fluid from the drill stringinto the annulus. In one arrangement, the bypass device for the pump canalso function as a particle bypass line for the APD device.Alternatively, a separate particle bypass can be used in addition to thepump bypass for such a function. Additionally, an annular seal (notshown) in certain embodiments can be disposed around the APD device toenable a pressure differential across the APD Device.

[0018] Examples of the more important features of the invention havebeen summarized (albeit rather broadly) in order that the detaileddescription thereof that follows may be better understood and in orderthat the contributions they represent to the art may be appreciated.There are, of course, additional features of the invention that will bedescribed hereinafter and which will form the subject of the claimsappended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

[0019] For detailed understanding of the present invention, referenceshould be made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawing:

[0020]FIG. 1A is a schematic illustration of one embodiment of a systemusing an active pressure differential device to manage pressure in apredetermined wellbore location;

[0021]FIG. 1B graphically illustrates the effect of an operating activepressure differential device upon the pressure at a predeterminedwellbore location;

[0022]FIG. 2 is a schematic elevation view of FIG. 1A after the drillstring and the active pressure differential device have moved a certaindistance in the earth formation from the location shown in FIG. 1A;

[0023]FIG. 3 is a schematic elevation view of an alternative embodimentof the wellbore system wherein the active pressure differential deviceis attached to the wellbore inside;

[0024] FIGS. 4A-D are schematic illustrations of one embodiment of anarrangement according to the present invention wherein a positivedisplacement motor is coupled to a positive displacement pump (the APDDevice);

[0025]FIGS. 5A and 5B are schematic illustrations of one embodiment ofan arrangement according to the present invention wherein a turbinedrive is coupled to a centrifugal pump (the APD Device);

[0026]FIG. 6A is a schematic illustration of an embodiment of anarrangement according to the present invention wherein an electric motordisposed on the outside of a drill string is coupled to an APD Device;and

[0027]FIG. 6B is a schematic illustration of an embodiment of anarrangement according to the present invention wherein an electric motordisposed within a drill string is coupled to an APD Device.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0028] Referring initially to FIG. 1A, there is schematicallyillustrated a system for performing one or more operations related tothe construction, logging, completion or work-over of a hydrocarbonproducing well. In particular, FIG. 1A shows a schematic elevation viewof one embodiment of a wellbore drilling system 100 for drillingwellbore 90 using conventional drilling fluid circulation. The drillingsystem 100 is a rig for land wells and includes a drilling platform 101,which may be a drill ship or another suitable surface workstation suchas a floating platform or a semi-submersible for offshore wells. Foroffshore operations, additional known equipment such as a riser andsubsea wellhead will typically be used. To drill a wellbore 90, wellcontrol equipment 125 (also referred to as the wellhead equipment) isplaced above the wellbore 90. The wellhead equipment 125 includes ablow-out-preventer stack 126 and a lubricator (not shown) with itsassociated flow control.

[0029] This system 100 further includes a well tool such as a drillingassembly or a bottomhole assembly (“BHA”) 135 at the bottom of asuitable umbilical such as drill string or tubing 121 (such terms willbe used interchangeably). In a preferred embodiment, the BHA 135includes a drill bit 130 adapted to disintegrate rock and earth. The bitcan be rotated by a surface rotary drive or a motor using pressurizedfluid (e.g., mud motor) or an electrically driven motor. The tubing 121can be formed partially or fully of drill pipe, metal or compositecoiled tubing, liner, casing or other known members. Additionally, thetubing 121 can include data and power transmission carriers such fluidconduits, fiber optics, and metal conductors. Conventionally, the tubing121 is placed at the drilling platform 101. To drill the wellbore 90,the BHA 135 is conveyed from the drilling platform 101 to the wellheadequipment 125 and then inserted into the wellbore 90. The tubing 121 ismoved into and out of the wellbore 90 by a suitable tubing injectionsystem.

[0030] During drilling, a drilling fluid from a surface mud system 22 ispumped under pressure down the tubing 121 (a “supply fluid”). The mudsystem 22 includes a mud pit or supply source 26 and one or more pumps28. In one embodiment, the supply fluid operates a mud motor in the BHA135, which in turn rotates the drill bit 130. The drill string 121rotation can also be used to rotate the drill bit 130, either inconjunction with or separately from the mud motor. The drill bit 130disintegrates the formation (rock) into cuttings 147. The drilling fluidleaving the drill bit travels uphole through the annulus 194 between thedrill string 121 and the wellbore wall or inside 196, carrying the drillcuttings 147 therewith (a “return fluid”). The return fluid dischargesinto a separator (not shown) that separates the cuttings 147 and othersolids from the return fluid and discharges the clean fluid back intothe mud pit 26. As shown in FIG. 1A, the clean mud is pumped through thetubing 121 while the mud with cuttings 147 returns to the surface viathe annulus 194 up to the wellhead equipment 125.

[0031] Once the well 90 has been drilled to a certain depth, casing 129with a casing shoe 151 at the bottom is installed. The drilling is thencontinued to drill the well to a desired depth that will include one ormore production sections, such as section 155. The section below thecasing shoe 151 may not be cased until it is desired to complete thewell, which leaves the bottom section of the well as an open hole, asshown by numeral 156.

[0032] As noted above, the present invention provides a drilling systemfor controlling bottomhole pressure at a zone of interest designated bythe numeral 155 and thereby the ECD effect on the wellbore. In oneembodiment of the present invention, to manage or control the pressureat the zone 155, an active pressure differential device (“APD Device”)170 is fluidicly coupled to return fluid downstream of the zone ofinterest 155. The active pressure differential device is a device thatis capable of creating a pressure differential “ΔP” across the device.This controlled pressure drop reduces the pressure upstream of the APDDevice 170 and particularly in zone 155.

[0033] The system 100 also includes downhole devices that separately orcooperatively perform one or more functions such as controlling the flowrate of the drilling fluid and controlling the flow paths of thedrilling fluid. For example, the system 100 can include one or moreflow-control devices that can stop the flow of the fluid in the drillstring and/or the annulus 194. FIG. 1A shows an exemplary flow-controldevice 173 that includes a device 174 that can block the fluid flowwithin the drill string 121 and a device 175 that blocks can block fluidflow through the annulus 194. The device 173 can be activated when aparticular condition occurs to insulate the well above and below theflow-control device 173. For example, the flow-control device 173 may beactivated to block fluid flow communication when drilling fluidcirculation is stopped so as to isolate the sections above and below thedevice 173, thereby maintaining the wellbore below the device 173 at orsubstantially at the pressure condition prior to the stopping of thefluid circulation.

[0034] The flow-control devices 174,175 can also be configured toselectively control the flow path of the drilling fluid. For example,the flow-control device 174 in the drill pipe 121 can be configured todirect some or all of the fluid in drill string 121 into the annulus194. Moreover, one or both of the flow-control devices 174, 175 can beconfigured to bypass some or all of the return fluid around the APDdevice 170. Such an arrangement may be useful, for instance, to assistin lifting cuttings to the surface. The flow-control device 173 mayinclude check-valves, packers and any other suitable device. Suchdevices may automatically activate upon the occurrence of a particularevent or condition.

[0035] The system 100 also includes downhole devices for processing thecuttings (e.g., reduction of cutting size) and other debris flowing inthe annulus 194. For example, a comminution device 176 can be disposedin the annulus 194 upstream of the APD device 170 to reduce the size ofentrained cutting and other debris. The comminution device 176 can useknown members such as blades, teeth, or rollers to crush, pulverize orotherwise disintegrate cuttings and debris entrained in the fluidflowing in the annulus 194. The comminution device 176 can be operatedby an electric motor, a hydraulic motor, by rotation of drill string orother suitable means. The comminution device 176 can also be integratedinto the APD device 170. For instance, if a multi-stage turbine is usedas the APD device 170, then the stages adjacent the inlet to the turbinecan be replaced with blades adapted to cut or shear particles beforethey pass through the blades of the remaining turbine stages.

[0036] Sensors S_(1−n) are strategically positioned throughout thesystem 100 to provide information or data relating to one or moreselected parameters of interest (pressure, flow rate, temperature). In apreferred embodiment, the downhole devices and sensors S_(1−n)communicate with a controller 180 via a telemetry system (not shown).Using data provided by the sensors S_(1−n), the controller 180 maintainsthe wellbore pressure at zone 155 at a selected pressure or range ofpressures. The controller 180 maintains the selected pressure bycontrolling the APD device 170 (e.g., adjusting amount of energy addedto the return fluid line) and/or the downhole devices (e.g., adjustingflow rate through a restriction such as a valve).

[0037] When configured for drilling operations, the sensors S_(1−n)provide measurements relating to a variety of drilling parameters, suchas fluid pressure, fluid flow rate, rotational speed of pumps and likedevices, temperature, weight-on bit, rate of penetration, etc., drillingassembly or BHA parameters, such as vibration, stick slip, RPM,inclination, direction, BHA location, etc. and formation or formationevaluation parameters commonly referred to as measurement-while-drillingparameters such as resistivity, acoustic, nuclear, NMR, etc. Onepreferred type of sensor is a pressure sensor for measuring pressure atone or more locations. Referring still to FIG. 1A, pressure sensor P₁provides pressure data in the BHA, sensor P₂ provides pressure data inthe annulus, pressure sensor P₃ in the supply fluid, and pressure sensorP₄ provides pressure data at the surface. Other pressure sensors may beused to provide pressure data at any other desired place in the system100. Additionally, the system 100 includes fluid flow sensors such assensor V that provides measurement of fluid flow at one or more placesin the system.

[0038] Further, the status and condition of equipment as well asparameters relating to ambient conditions (e.g., pressure and otherparameters listed above) in the system 100 can be monitored by sensorspositioned throughout the system 100: exemplary locations including atthe surface (S1), at the APD device 170 (S2), at the wellhead equipment125 (S3), in the supply fluid (S4), along the tubing 121 (S5), at thewell tool 135 (S6), in the return fluid upstream of the APD device 170(S7), and in the return fluid downstream of the APD device 170 (S8). Itshould be understood that other locations may also be used for thesensors S_(1−n).

[0039] The controller 180 for suitable for drilling operationspreferably includes programs for maintaining the wellbore pressure atzone 155 at under-balance condition, at at-balance condition or atover-balanced condition. The controller 180 includes one or moreprocessors that process signals from the various sensors in the drillingassembly and also controls their operation. The data provided by thesesensors S_(1−n) and control signals transmitted by the controller 180 tocontrol downhole devices such as devices 173-176 are communicated by asuitable two-way telemetry system (not shown). A separate processor maybe used for each sensor or device. Each sensor may also have additionalcircuitry for its unique operations. The controller 180, which may beeither downhole or at the surface, is used herein in the generic sensefor simplicity and ease of understanding and not as a limitation becausethe use and operation of such controllers is known in the art. Thecontroller 180 preferably contains one or more microprocessors ormicro-controllers for processing signals and data and for performingcontrol functions, solid state memory units for storing programmedinstructions, models (which may be interactive models) and data, andother necessary control circuits. The microprocessors control theoperations of the various sensors, provide communication among thedownhole sensors and provide two-way data and signal communicationbetween the drilling assembly 30, downhole devices such as devices173-175 and the surface equipment via the two-way telemetry. In otherembodiments, the controller 180 can be a hydro-mechanical device thatincorporates known mechanisms (valves, biased members, linkagescooperating to actuate tools under, for example, preset conditions).

[0040] For convenience, a single controller 180 is shown. It should beunderstood, however, that a plurality of controllers 180 can also beused. For example, a downhole controller can be used to collect, processand transmit data to a surface controller, which further processes thedata and transmits appropriate control signals downhole. Othervariations for dividing data processing tasks and generating controlsignals can also be used.

[0041] In general, however, during operation, the controller 180receives the information regarding a parameter of interest and adjustsone or more downhole devices and/or APD device 170 to provide thedesired pressure or range or pressure in the vicinity of the zone ofinterest 155. For example, the controller 180 can receive pressureinformation from one or more of the sensors (S₁−S_(n)) in the system100. The controller 180 may control the APD Device 170 in response toone or more of: pressure, fluid flow, a formation characteristic, awellbore characteristic and a fluid characteristic, a surface measuredparameter or a parameter measured in the drill string. The controller180 determines the ECD and adjusts the energy input to the APD device170 to maintain the ECD at a desired or predetermined value or within adesired or predetermined range. The wellbore system 100 thus provides aclosed loop system for controlling the ECD in response to one or moreparameters of interest during drilling of a wellbore. This system isrelatively simple and efficient and can be incorporated into new orexisting drilling systems and readily adapted to support other wellconstruction, completion, and work-over activities.

[0042] In the embodiment shown in FIG. 1A, the APD Device 170 is shownas a turbine attached to the drill string 121 that operates within theannulus 194. Other embodiments, described in further detail below caninclude centrifugal pumps, positive displacement pump, jet pumps andother like devices. During drilling, the APD Device 170 moves in thewellbore 90 along with the drill string 121. The return fluid can flowthrough the APD Device 170 whether or not the turbine is operating.However, the APD Device 170, when operated creates a differentialpressure thereacross.

[0043] As described above, the system 100 in one embodiment includes acontroller 180 that includes a memory and peripherals 184 forcontrolling the operation of the APD Device 170, the devices 173-176,and/or the bottomhole assembly 135. In FIG. 1A, the controller 180 isshown placed at the surface. It, however, may be located adjacent theAPD Device 170, in the BHA 135 or at any other suitable location. Thecontroller 180 controls the APD Device to create a desired amount of ΔPacross the device, which alters the bottomhole pressure accordingly.Alternatively, the controller 180 may be programmed to activate theflow-control device 173 (or other downhole devices) according toprogrammed instructions or upon the occurrence of a particularcondition. Thus, the controller 180 can control the APD Device inresponse to sensor data regarding a parameter of interest, according toprogrammed instructions provided to said APD Device, or in response toinstructions provided to said APD Device from a remote location. Thecontroller 180 can, thus, operate autonomously or interactively.

[0044] During drilling, the controller 180 controls the operation of theAPD Device to create a certain pressure differential across the deviceso as to alter the pressure on the formation or the bottomhole pressure.The controller 180 may be programmed to maintain the wellbore pressureat a value or range of values that provide an under-balance condition,an at-balance condition or an over-balanced condition. In oneembodiment, the differential pressure may be altered by altering thespeed of the APD Device. For instance, the bottomhole pressure may bemaintained at a preselected value or within a selected range relative toa parameter of interest such as the formation pressure. The controller180 may receive signals from one or more sensors in the system 100 andin response thereto control the operation of the APD Device to createthe desired pressure differential. The controller 180 may containpre-programmed instructions and autonomously control the APD Device orrespond to signals received from another device that may be remotelylocated from the APD Device.

[0045]FIG. 1B graphically illustrates the ECD control provided by theabove-described embodiment of the present invention and references FIG.1A for convenience. FIG. 1A shows the APD device 170 at a depth D1 and arepresentative location in the wellbore in the vicinity of the well tool30 at a lower depth D2. FIG. 1B provides a depth versus pressure graphhaving a first curve C1 representative of a pressure gradient beforeoperation of the system 100 and a second curve C2 representative of apressure gradients during operation of the system 100. Curve C3represents a theoretical curve wherein the ECD condition is not present;i.e., when the well is static and not circulating and is free of drillcuttings. It will be seen that a target or selected pressure at depth D2under curve C3 cannot be met with curve C1. Advantageously, the system100 reduces the hydrostatic pressure at depth D1 and thus shifts thepressure gradient as shown by curve C3, which can provide the desiredpredetermined pressure at depth D2. In most instances, this shift isroughly the pressure drop provided by the APD device 170.

[0046]FIG. 2 shows the drill string after it has moved the distance “d”shown by t₁-t₂. Since the APD Device 170 is attached to the drill string121, the APD Device 170 also is shown moved by the distance d.

[0047] As noted earlier and shown in FIG. 2, an APD Device 170 a may beattached to the wellbore in a manner that will allow the drill string121 to move while the APD Device 170 a remains at a fixed location. FIG.3 shows an embodiment wherein the APD Device is attached to the wellboreinside and is operated by a suitable device 172 a. Thus, the APD devicecan be attached to a location stationary relative to said drill stringsuch as a casing, a liner, the wellbore annulus, a riser, or othersuitable wellbore equipment. The APD Device 170 a is preferablyinstalled so that it is in a cased upper section 129. The device 170 ais controlled in the manner described with respect to the device 170(FIG. 1A).

[0048] Referring now to FIGS. 4A-D, there is schematically illustratedone arrangement wherein a positive displacement motor/drive 200 iscoupled to a moineau-type pump 220 via a shaft assembly 240. The motor200 is connected to an upper string section 260 through which drillingfluid is pumped from a surface location. The pump 220 is connected to alower drill string section 262 on which the bottomhole assembly (notshown) is attached at an end thereof. The motor 200 includes a rotor 202and a stator 204. Similarly, the pump 220 includes a rotor 222 and astator 224. The design of moineau-type pumps and motors are known to oneskilled in the art and will not be discussed in further detail.

[0049] The shaft assembly 240 transmits the power generated by the motor200 to the pump 220. One preferred shaft assembly 240 includes a motorflex shaft 242 connected to the motor rotor 202, a pump flex shaft 244connected to the pump rotor 224, and a coupling shaft 246 for joiningthe first and second shafts 242 and 244. In one arrangement, ahigh-pressure seal 248 is disposed about the coupling shaft 246. As isknown, the rotors for moineau-type motors/pump are subject to eccentricmotion during rotation. Accordingly, the coupling shaft 246 ispreferably articulated or formed sufficiently flexible to absorb thiseccentric motion. Alternately or in combination, the shafts 242, 244 canbe configured to flex to accommodate eccentric motion. Radial and axialforces can be borne by bearings 250 positioned along the shaft assembly240. In a preferred embodiment, the seal 248 is configured to beareither or both of radial and axial (thrust) forces. In certainarrangements, a speed or torque converter 252 can be used to convertspeed/torque of the motor 200 to a second speed/torque for the pump 220.By speed/torque converter it is meant known devices such as variable orfixed ratio mechanical gearboxes, hydrostatic torque converters, and ahydrodynamic converters. It should be understood that any number ofarrangements and devices can be used to transfer power, speed, or torquefrom the motor 200 to the pump 220. For example, the shaft assembly 240can utilize a single shaft instead of multiple shafts.

[0050] As described earlier, a comminution device can be used to processentrained cutting in the return fluid before it enters the pump 200.Such a comminution device (FIG. 1A) can be coupled to the drive 200 orpump 220 and operated thereby. For instance, one such comminution deviceor cutting mill 270 can include a shaft 272 coupled to the pump rotor224. The shaft 272 can include a conical head or hammer element 274mounted thereon. During rotation, the eccentric motion of the pump rotor224 will cause a corresponding radial motion of the shaft head 274. Thisradial motion can be used to resize the cuttings between the rotor and acomminution device housing 276.

[0051] The FIGS. 4A-D arrangement also includes a supply flow path 290to carry supply fluid from the device 200 to the lower drill stringsection 262 and a return flow path 292 to channel return fluid from thecasing interior or annulus into and out of the pump 220. The highpressure seal 248 is interposed between the flow paths 290 and 292 toprevent fluid leaks, particularly from the high pressure fluid in thesupply flow path 290 into the return flow path 292. The seal 248 can bea high-pressure seal, a hydrodynamic seal or other suitable seal andformed of rubber, an elastomer, metal or composite.

[0052] Additionally, bypass devices are provided to allow fluidcirculation during tripping of the downhole devices of the system 100(FIG. 1A), to control the operating set points of the motor 200 and pump220, and to provide safety pressure relief along either or both of thesupply flow path 290 and the return flow path 292. Exemplary bypassdevices include a circulation bypass 300, motor bypass 310, and a pumpbypass 320.

[0053] The circulation bypass 300 selectively diverts supply fluid intothe annulus 194 (FIG. 1A) or casing C interior. The circulation bypass300 is interposed generally between the upper drill string section 260and the motor 200. One preferred circulation bypass 300 includes abiased valve member 302 that opens when the flow-rate drops below apredetermined valve. When the valve 302 is open, the supply fluid flowsalong a channel 304 and exits at ports 306. More generally, thecirculation bypass can be configured to actuate upon receiving anactuating signal and/or detecting a predetermined value or range ofvalues relating to a parameter of interest (e.g., flow rate or pressureof supply fluid or operating parameter of the bottomhole assembly). Thecirculation bypass 300 can be used to facilitate drilling operations andto selective increase the pressure/flow rate of the return fluid.

[0054] The motor bypass 310 selectively channels conveys fluid aroundthe motor 200. The motor bypass 310 includes a valve 312 and a passage314 formed through the motor rotor 202. A joint 316 connecting the motorrotor 202 to the first shaft 242 includes suitable passages (not shown)that allow the supply fluid to exit the rotor passage 314 and enter thesupply flow path 290. Likewise, a pump bypass 320 selectively conveysfluid around the pump 220. The pump bypass includes a valve and apassage formed through the pump rotor 222 or housing. The pump bypass320 can also be configured to function as a particle bypass line for theAPD device. For example, the pump bypass can be adapted with knownelements such as screens or filters to selectively convey cuttings orparticles entrained in the return fluid that are greater than apredetermined size around the APD device. Alternatively, a separateparticle bypass can be used in addition to the pump bypass for such afunction. Alternately, a valve (not shown) in a pump housing 225 candivert fluid to a conduit parallel to the pump 220. Such a valve can beconfigured to open when the flow rate drops below a predetermined value.Further, the bypass device can be a design internal leakage in the pump.That is, the operating point of the pump 220 can be controlled byproviding a preset or variable amount of fluid leakage in the pump 220.Additionally, pressure valves can be positioned in the pump 220 todischarge fluid in the event an overpressure condition or otherpredetermined condition is detected.

[0055] Additionally, an annular seal 299 in certain embodiments can bedisposed around the APD device to direct the return fluid to flow intothe pump 220 (or more generally, the APD device) and to allow a pressuredifferential across the pump 220. The seal 299 can be a solid or pliantring member, an expandable packer type element that expands/contractsupon receiving a command signal, or other member that substantiallyprevents the return fluid from flowing between the pump 220 (or moregenerally, the APD device) and the casing or wellbore wall. In certainapplications, the clearance between the APD device and adjacent wall(either casing or wellbore) may be sufficiently small as to not requirean annular seal.

[0056] During operation, the motor 200 and pump 220 are positioned in awell bore location such as in a casing C. Drilling fluid (the supplyfluid) flowing through the upper drill string section 260 enters themotor 200 and causes the rotor 202 to rotate. This rotation istransferred to the pump rotor 222 by the shaft assembly 240. As isknown, the respective lobe profiles, size and configuration of the motor200 and the pump 220 can be varied to provide a selected speed or torquecurve at given flow-rates. Upon exiting the motor 200, the supply fluidflows through the supply flow path 290 to the lower drill string section262, and ultimately the bottomhole assembly (not shown). The returnfluid flows up through the wellbore annulus (not shown) and casing C andenters the cutting mill 270 via a inlet 293 for the return flow path292. The flow goes through the cutting mill 270 and enters the pump 220.In this embodiment, the controller 180 (FIG. 1A) can be programmed tocontrol the speed of the motor 200 and thus the operation of the pump220 (the APD Device in this instance).

[0057] It should be understood that the above-described arrangement ismerely one exemplary use of positive displacement motors and pumps. Forexample, while the positive displacement motor and pump are shown instructurally in series in FIGS. 4A-D, a suitable arrangement can alsohave a positive displacement motor and pump in parallel. For example,the motor can be concentrically disposed in a pump.

[0058] Referring now to FIGS. 5A-B, there is schematically illustratedone arrangement wherein a turbine drive 350 is coupled to acentrifugal-type pump 370 via a shaft assembly 390. The turbine 350includes stationary and rotating blades 354 and radial bearings 402. Thecentrifugal-type pump 370 includes a housing 372 and multiple impellerstages 374. The design of turbines and centrifugal pumps are known toone skilled in the art and will not be discussed in further detail.

[0059] The shaft assembly 390 transmits the power generated by theturbine 350 to the centrifugal pump 370. One preferred shaft assembly350 includes a turbine shaft 392 connected to the turbine blade assembly354, a pump shaft 394 connected to the pump impeller stages 374, and acoupling 396 for joining the turbine and pump shafts 392 and 394.

[0060] The FIG. 5A-B arrangement also includes a supply flow path 410for channeling supply fluid shown by arrows designated 416 and a returnflow path 418 to channel return fluid shown by arrows designated 424.The supply flow path 410 includes an inlet 412 directing supply fluidinto the turbine 350 and an axial passage 413 that conveys the supplyfluid exiting the turbine 350 to an outlet 414. The return flow path 418includes an inlet 420 that directs return fluid into the centrifugalpump 370 and an outlet 422 that channels the return fluid into thecasing C interior or wellbore annulus. A high pressure seal 400 isinterposed between the flow paths 410 and 418 to reduce fluid leaks,particularly from the high pressure fluid in the supply flow path 410into the return flow path 418. A small leakage rate is desired to cooland lubricate the axial and radial bearings. Additionally, a bypass 426can be provided to divert supply fluid from the turbine 350. Moreover,radial and axial forces can be borne by bearing assemblies 402positioned along the shaft assembly 390. Preferably a comminution device373 is provided to reduce particle size entering the centrifugal pump370. In a preferred embodiment, one of the impeller stages is modifiedwith shearing blades or elements that shear entrained particles toreduce their size. In certain arrangements, a speed or torque converter406 can be used to convert a first speed/torque of the motor 350 to asecond speed/torque for the centrifugal pump 370. It should beunderstood that any number of arrangements and devices can be used totransfer power, speed, or torque from the turbine 350 to the pump 370.For example, the shaft assembly 390 can utilize a single shaft insteadof multiple shafts.

[0061] It should be appreciated that a positive displacement pump neednot be matched with only a positive displacement motor, or a centrifugalpump with only a turbine. In certain applications, operational speed orspace considerations may lend itself to an arrangement wherein apositive displacement drive can effectively energize a centrifugal pumpor a turbine drive energize a positive displacement pump. It should alsobe appreciated that the present invention is not limited to theabove-described arrangements. For example, a positive displacement motorcan drive an intermediate device such as an electric motor or hydraulicmotor provided with an encapsulated clean hydraulic reservoir. In suchan arrangement, the hydraulic motor (or produced electric power) drivesthe pump. These arrangements can eliminate the leak paths between thehigh-pressure supply fluid and the return fluid and therefore eliminatesthe need for high-pressure seals. Alternatively, a jet pump can be used.In an exemplary arrangement, the supply fluid is divided into twostreams. The first stream is directed to the BHA. The second stream isaccelerated by a nozzle and discharged with high velocity into theannulus, thereby effecting a reduction in annular pressure. Pumpsincorporating one or more pistons, such as hammer pumps, may also besuitable for certain applications.

[0062] Referring now to FIG. 6A, there is schematically illustrated onearrangement wherein an electrically driven pump assembly 500 includes amotor 510 that is at least partially positioned external to a drillstring 502. In a conventional manner, the motor 510 is coupled to a pump520 via a shaft assembly 530. A supply flow path 504 conveys supplyfluid designated with arrow 505 and a return flow path 506 conveysreturn fluid designated with arrow 507. As can be seen, the FIG. 6Aarrangement does not include leak paths through which the high-pressuresupply fluid 505 can invade the return flow path 506. Thus, there is noneed for high pressures seals.

[0063] In one embodiment, the motor 510 includes a rotor 512, a stator514, and a rotating seal 516 that protects the coils 512 and stator 514from drilling fluid and cuttings. In one embodiment, the stator 514 isfixed on the outside of the drill string 502. The coils of the rotor 512and stator 514 are encapsulated in a material or housing that preventsdamage from contact with wellbore fluids. Preferably, the motor 510interiors are filled with a clean hydraulic fluid. In another embodimentnot shown, the rotor is positioned within the flow of the return fluid,thereby eliminating the rotating seal. In such an arrangement, thestator can be protected with a tube filled with clean hydraulic fluidfor pressure compensation.

[0064] Referring now to FIG. 6B, there is schematically illustrated onearrangement wherein an electrically driven pump 550 includes a motor 570that is at least partially formed integral with a drill string 552. In aconventional manner, the motor 570 is coupled to a pump 590 via a shaftassembly 580. A supply flow path 554 conveys supply fluid designatedwith arrow 556 and a return flow path 558 conveys return fluiddesignated with arrow 560. As can be seen, the FIG. 6B arrangement doesnot include leak paths through which the high-pressure supply fluid 556can invade the return flow path 558. Thus, there is no need for highpressures seals.

[0065] It should be appreciated that an electrical drive provides arelatively simple method for controlling the APD Device. For instance,varying the speed of the electrical motor will directly control thespeed of the rotor in the APD device, and thus the pressure differentialacross the APD Device. Further, in either of the FIG. 6A or 6Barrangements, the pump 520 and 590 can be any suitable pump, and ispreferably a multi-stage centrifugal-type pump. Moreover, positivedisplacement type pumps such a screw or gear type or moineau-type pumpsmay also be adequate for many applications. For example, the pumpconfiguration may be single stage or multi-stage and utilize radialflow, axial flow, or mixed flow. Additionally, as described earlier, acomminution device positioned downhole of the pumps 520 and 590 can beused to reduce the size of particles entrained in the return fluid.

[0066] It will be appreciated that many variations to theabove-described embodiments are possible. For example, a clutch elementcan be added to the shaft assembly connecting the drive to the pump toselectively couple and uncouple the drive and pump. Further, in certainapplications, it may be advantages to utilize a non-mechanicalconnection between the drive and the pump. For instance, a magneticclutch can be used to engage the drive and the pump. In such anarrangement, the supply fluid and drive and the return fluid and pumpcan remain separated. The speed/torque can be transferred by a magneticconnection that couples the drive and pump elements, which are separatedby a tubular element (e.g., drill string). Additionally, while certainelements have been discussed with respect to one or more particularembodiments, it should be understood that the present invention is notlimited to any such particular combinations. For example, elements suchas shaft assemblies, bypasses, comminution devices and annular sealsdiscussed in the context of positive displacement drives can be readilyused with electric drive arrangements. Other embodiments within thescope of the present invention that are not shown include a centrifugalpump that is attached to the drill string. The pump can include amulti-stage impeller and can be driven by a hydraulic power unit, suchas a motor. This motor may be operated by the drilling fluid or by anyother suitable manner. Still another embodiment not shown includes anAPD Device that is fixed to the drill string, which is operated by thedrill string rotation. In this embodiment, a number of impellers areattached to the drill string. The rotation of the drill string rotatesthe impeller that creates a differential pressure across the device.

[0067] While the foregoing disclosure is directed to the preferredembodiments of the invention, various modifications will be apparent tothose skilled in the art. It is intended that all variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

What is claimed is:
 1. A drilling system for drilling a wellbore,comprising (a) a drill string having a drill bit at an end thereof; (b)a source of drilling fluid supplying drilling fluid under pressure intothe drill string (a “supply fluid”), the drilling fluid returning upholevia an annulus around the drill string (a “return fluid”); (c) an activepressure differential device (“APD Device”) associated with the returnfluid to create a pressure drop across said APD Device to reducepressure in the wellbore downhole of said APD Device; (d) a driveassembly coupled to said APD Device for energizing said APD Device; and(e) a sealing member positioned between said APD Device and said driveassembly, said sealing member at least partially providing a barrierbetween the supply fluid and the return fluid.
 2. The drilling system ofclaim 1 wherein said APD Device is selected from one of (a) a positivedisplacement pump, (b) a centrifugal type pump, and (c) a Moineau-typepump.
 3. The drilling system of claim 1 wherein said drive assembly isselected from one of (a) a positive displacement drive, (b) a turbinedrive, (c) a electric motor, (d) a hydraulic motor, (e) a Moineau-typemotor, and (f) rotation of said drill string.
 4. The drilling system ofclaim 1 further comprising a bypass for selectively diverting fluidaround one of said APD device and said drive assembly.
 5. The drillingsystem of claim 1 further comprising a speed converter interposedbetween drive assembly and said APD device, said speed converter beingadapted to convert a first speed associated with said drive assembly toa selected second speed associated with said APD device.
 6. The drillingsystem of claim 5 wherein said speed converter is selected from a groupconsisting of (i) a gear drive, (ii) a hydrostatic drive, and (iii) ahydrodynamic drive.
 7. The drilling system of claim 1 further comprisinga comminution device positioned downhole of said APD device, saidcomminution device configured to reduce the size of cuttings entrainedin the return fluid.
 8. The drilling system of claim 7 wherein saidcomminution device includes a shaft coupled to a rotor associated withsaid APD Device and a conical head mounted on an end thereof, said shafthaving a radial motion corresponding to an eccentric motion of saidrotor, said conical head thereby engaging and reducing the size of thecuttings.
 9. The drilling system of claim 1 wherein said APD Devicecomprises a centrifugal type pump and said comminution device comprisesa shearing member configured as a stage in said centrifugal type pump.10. The drilling system of claim 1 further comprising an annular sealdisposed around said APD device, said annular seal causing the returnfluid to flow into said APD device and allowing said APD device tocreate a differential pressure thereacross.
 11. The drilling system ofclaim 1 further comprising a controller that controls the operation ofsaid APD Device.
 12. The drilling system of claim 11 wherein saidcontroller is located at one of: (i) at the surface; (ii) in a drillingassembly attached to the drill string; and (iii) adjacent said APDDevice.
 13. The drilling system of claim 11 wherein said controllercontrols said APD Device in response to one of: (i) a parameter ofinterest; (ii) programmed instructions provided to said controller;(iii) instructions from a remote location; and (iv) a downhole measuredparameter.
 14. The drilling system of claim 11 wherein said controllerincludes one of (a) microprocessor and a memory, and (b) ahydro-mechanical device.
 15. The drilling system of claim 11 whereinsaid controller is positioned in the wellbore; and further comprises atelemetry system for transmitting signals to said controller.
 16. Thedrilling system of claim 11 wherein said controller controls theoperation of said APD Device to control the pressure in the wellbore toone of: (i) maintain the wellbore bottomhole pressure at a predeterminedvalue; (ii) maintain the wellbore bottomhole pressure within a selectedrange; (iii) maintain at-balance condition; and (iv) maintainunder-balance condition.
 17. The drilling system of claim 1 furthercomprising a sensor for detecting a parameter of interest.
 18. Thedrilling system of claim 17 wherein said sensor detects a parameterselected from a group consisting of (i) drilling parameters, (ii)drilling assembly parameters, and (iii) formation evaluation parameters.19. The drilling system of claim 17 wherein said sensor is positioned ata predetermined location selected from a group consisting of (i) asurface location, (ii) at said APD Device, (iii) at wellhead equipment,(iv) in the supply fluid, (v) along said drill string, (vi) at adrilling assembly connected to said drill string, (vii) in the returnfluid upstream of said APD device, and (viii) in the return fluiddownstream of said APD device.
 20. The drilling system of claim 1further comprising a blocking device downhole of said APD Device thatblocks the return fluid flow when the drilling fluid supply isinterrupted or stopped.
 21. The drilling system of claim 1 wherein saidAPD device is attached to one of (a) said drill string, (b) a locationstationary relative to said drill string, (c) the annulus, and (d) ariser.
 22. A drilling system for drilling a wellbore, comprising (a) adrill string having a drill bit at an end thereof; (b) a source ofdrilling fluid supplying drilling fluid under pressure into the drillstring (a “supply fluid”), said drilling fluid returning uphole via anannulus around the drill string (a “return fluid”); (c) an activepressure differential device (“APD Device”) placed in the annulus tocreate a pressure drop across said APD Device to reduce pressure in thewellbore downhole of said APD Device, said APD Device in fluidcommunication with the return fluid; and (d) an electric drive assemblybeing substantially isolated from the supply fluid.
 23. The drillingsystem of claim 22 wherein said electric drive assembly is disposed in alocation selected from (a) in housing that substantially isolates saidelectric drive assembly from the supply fluid, and (b) on the outside ofsaid drill string.
 24. The drilling system of claim 22 furthercomprising a speed converter interposed between said drive assembly andsaid APD device, said speed converter adapted to convert a first speedassociated with said drive assembly to a selected second speedassociated with said APD device.
 25. The drilling system of claim 24wherein said speed converter is selected from a group consisting of (i)a gear drive, (ii) a hydrodynamic drive, and (iii) a hydrodynamic drive.26. The drilling system of claim 22 further comprising a comminutiondevice positioned downhole of said APD device, said comminution deviceconfigured to reduce the size of particles entrained in said drillingfluid.
 27. The drilling system of claim 26 wherein said comminutiondevice is coupled to said drive assembly and energized thereby.
 28. Thedrilling system of claim 26 wherein said comminution device comprises ashearing member configured as a stage in a centrifugal type pumpassociated with said APD Device.
 29. The drilling system of claim 22further comprising an annular seal disposed around said APD device, saidannular seal causing drilling fluid to flow into said APD device. 30.The drilling system of claim 22 wherein said APD Device includes one of:(i) a turbine; and (ii) a centrifugal pump.
 31. A method for drilling awellbore, comprising (a) providing a drill string having a drill bit atan end thereof; (b) supplying drilling fluid under pressure into thedrill string (a “supply fluid”), the drilling fluid returning uphole viaan annulus around the drill string (a “return fluid”); (c) positioningan active pressure differential device (“APD Device”) in fluidcommunication with the return fluid to create a pressure drop across theAPD Device to reduce pressure in the wellbore downhole of the APDDevice; (d) coupling a drive assembly to the APD Device for energizingsaid APD Device; and (e) providing an at least partial barrier betweenthe supply fluid and the return fluid by positioning a sealing memberpositioned between the APD Device and the drive assembly.
 32. The methodof claim 31 wherein said APD Device is selected from one of (a) apositive displacement pump, (b) a centrifugal type pump, and (c) aMoineau-type pump.
 33. The method of claim 31 wherein said driveassembly is operated by one of (a) a positive displacement drive, (b) aturbine drive, (c) a electric motor, (d) a hydraulic motor, (e) aMoineau-type pump, and (f) rotation of the drill string.
 34. The methodof claim 31 further comprising positioning a comminution device downholeof the APD device, the comminution device configured to reduce the sizeof cuttings entrained in the return fluid.
 35. The method of claim 34wherein the comminution device includes a shaft coupled to a rotorassociated with the APD Device and a conical head mounted on an endthereof, the shaft having a radial motion corresponding to an eccentricmotion of the rotor, the conical head thereby engaging and reducing thesize of the cuttings.
 36. The method of claim 34 wherein the APD Devicecomprises a centrifugal type pump and the comminution device comprises ashearing member configured as a stage in the centrifugal type pump. 37.The method of claim 31 further comprising disposing an annular sealaround the APD device, the annular seal causing the return fluid to flowinto the APD device and allowing the APD device to create a differentialpressure.
 38. The method of claim 31 further comprising controlling theoperation of the APD Device with a controller.
 39. The method of claim38 further comprising positioning the controller at one of: (i) at thesurface; (ii) in a drilling assembly attached to the drill string; and(iii) adjacent the APD Device.
 40. The method of claim 38 wherein thecontroller controls the APD Device in response to of: (i) a parameter ofinterest; (ii) programmed instructions provided to the APD Device; (iii)instructions provided to the APD Device from a remote location; and (iv)a downhole detected parameter.
 41. The method of claim 38 furthercomprising positioning the controller in the wellbore; and transmittingsignals to the controller via a telemetry system.
 42. The method ofclaim 38 wherein the controller controls the operation of the APD Deviceto control the pressure in the wellbore to one of: (i) maintain thewellbore bottomhole pressure at a predetermined value; (ii) maintain thewellbore bottomhole pressure within a selected range; (iii) maintainat-balance condition; and (iv) maintain under-balance condition.
 43. Themethod of claim 31 further comprising detecting a parameter of interestwith a sensor.
 44. The method of claim 43 wherein the sensor detects aparameter selected from a group consisting of (i) drilling parameters,(ii) drilling assembly parameters, and (iii) formation evaluationparameters.
 45. The method of claim 43 further comprising positioningthe sensor at a predetermined location selected from a group consistingof (i) a surface location, (ii) at the APD Device, (iii) at wellheadequipment, (iv) in the supply fluid, (v) along the drill string, (vi) ata drilling assembly connected to the drill string, (vii) in the returnfluid upstream of the APD device, and (viii) in the return fluiddownstream of the APD device.
 46. The method of claim 31 furthercomprising attaching the APD device to one of (a) the drill string, (b)a location stationary relative to the drill string, (c) the annulus, and(d) a riser.
 47. A method for drilling a wellbore, comprising (a)providing a drill string having a drill bit at an end thereof; (b)supplying drilling fluid under pressure into the drill string (a “supplyfluid”), the drilling fluid returning uphole via an annulus around thedrill string (a “return fluid”); (c) placing an active pressuredifferential device (“APD Device”) in the annulus to create a pressuredrop across the APD Device to reduce pressure in the wellbore downholeof the APD Device, the APD Device in fluid communication with the returnfluid; and (d) driving the APD device with an electric drive assemblythat is substantially isolated from the supply fluid.
 48. The method ofclaim 47 further comprising disposing the electric drive assembly in alocation selected from (a) in housing that substantially isolates theelectric drive assembly from the supply fluid, and (b) on the outside ofthe drill string.
 49. The method of claim 47 further comprisingpositioning a comminution device downhole of the APD device, thecomminution device configured to reduce the size of particles entrainedin the return fluid.
 50. The method of claim 47 further comprisingdisposing an annular seal around the APD device, the annular sealcausing drilling fluid to flow into the APD device and providing apressure differential across the APD device.
 51. The method of claim 47wherein said APD Device includes one of: (i) a turbine; and (ii) acentrifugal pump.